1. Field of Invention
The present invention relates generally to rotating control device (“RCD”) sealing elements. In particular, the present invention relates to RCD sealing elements having two or more elastomeric materials.
2. Background Art
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. When weight is applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. Because of the energy and friction involved in drilling a wellbore in the earth's formation, drilling fluids, commonly referred to as drilling mud, are used to lubricate and cool the drill bit as it cuts the rock formations below. Furthermore, in addition to cooling and lubricating the drill bit, drilling mud also performs the secondary and tertiary functions of removing the drill cuttings from the bottom of the wellbore and applying a hydrostatic column of pressure to the drilled wellbore.
Typically, drilling mud is delivered to the drill bit from the surface under high pressures through a central bore of the drillstring. From there, nozzles on the drill bit direct the pressurized mud to the cutters on the drill bit where the pressurized mud cleans and cools the bit. As the fluid is delivered downhole through the central bore of the drillstring, the fluid returns to the surface in an annulus formed between the outside of the drillstring and the inner profile of the drilled wellbore. Because the ratio of the cross-sectional area of the drillstring bore to the annular area is relatively low, drilling mud returning to the surface through the annulus does so at lower pressures and velocities than it is delivered. Nonetheless, a hydrostatic column of drilling mud typically extends from the bottom of the hole up to a bell nipple of a diverter assembly on the drilling rig. Annular fluids exit the bell nipple where solids are removed, the mud is processed, and then prepared to be re-delivered to the subterranean wellbore through the drillstring.
As wellbores are drilled several thousand feet below the surface, the hydrostatic column of drilling mud serves to help prevent blowout of the wellbore as well. Often, hydrocarbons and other fluids trapped in subterranean formations exist under significant pressures. Absent any flow control schemes, fluids from such ruptured formations may blow out of the wellbore and spew hydrocarbons and other undesirable fluids (e.g., H2S gas).
Further, under certain circumstances, the drill bit will encounter pockets of pressurized formations and will cause the wellbore to “kick” or experience a rapid increase in pressure. Because formation kicks are unpredictable and would otherwise result in disaster, flow control devices known as blowout preventers (“BOPs”), are mandatory on most wells drilled today. One type of BOP is an annular blowout preventer. Annular BOPs are configured to seal the annular space between the drill string and the inside of the wellbore. Annular BOPs typically include a large flexible rubber packing unit of a substantially toroidal shape that is configured to seal around a variety of drill string sizes when activated by a piston. Furthermore, when no drill string is present, annular BOPs may even be capable of sealing an open bore. While annular BOPs are configured to allow a drill string to be removed (i.e., tripped out) or inserted (i.e., tripped in) therethrough while actuated, they are not configured to be actuated during drilling operations (i.e., while the drill string is rotating). Because of their configuration, rotating the drill string through an activated annular blowout preventer would rapidly wear out the packing element, thus causing the blowout preventer to be less capable of sealing the well in the event of a blowout.
Thus, rotating control devices (“RCD”) are frequently used in oilfield drilling operations where elevated annular pressures are present to seal around drill string components and prevent fluids in the wellbore from escaping. For example, conventional RCDs may be capable of isolating pressures in excess of 1,000 psi while rotating (i.e., dynamic) and 2,000 psi when not rotating (i.e., static). A typical RCD includes a packing element and a bearing package, whereby the bearing package allows the packing element to rotate along with the drillstring. Therefore, in using a RCD, there is no relative rotational movement between the packing element and the drillstring, only the bearing package exhibits relative rotational movement. Examples of RCDs include U.S. Pat. No. 5,022,472 issued to Bailey et al. on Jun. 11, 1991 (assigned to Drilex Systems), and U.S. Pat. No. 6,354,385 issued to Ford et al. on Mar. 12, 2002, assigned to the assignee of the present application, and both are hereby incorporated by reference herein in their entirety. In some instances, dual stripper rotating control devices having two sealing elements, one of which is a primary seal and the other a backup seal, may be used.
A typical RCD is shown in FIG. 1, wherein an RCD 100 includes a sealing element 110 (also referred to as a “stripper element”), which acts as a passive seal that maintains a constant barrier between the atmosphere and wellbore. In particular, the RCD 100 is in fluid communication with the wellbore during drilling operations. The pressure within the wellbore may be exerted upon the sealing element 110 of the RCD 100 that seals against drill string 160. The sealing element 110 is bolted to a drive-bushing 120 with bolt 122, and a drive-ring 130 is connected to the drive-bushing 120 such that the drive-ring 130 turns with the drive-bushing 120. A lower-sleeve 140 is attached to the drive-ring 130 opposite from the drive-bushing 120. A bearing package 150 surrounds the drive-ring 130 and lower-sleeve 140, wherein roller-bearings 152 are disposed between the bearing package 150 and the drive-ring 130, and a dynamic seals stack 154 is disposed between the bearing package 150 and the lower-sleeve 140. Drill string 160 extends from a drilling rig (not shown) through the sealing element 110 and into the wellbore (not shown). In underwater drilling operations, the drill string may extend from the drilling rig, through a riser and to the wellbore through the subsea wellhead as if the riser sections are a mere extension of the wellbore itself.
Typically, a drill string includes a plurality of the drill pipes connected by threaded connections located on both ends of the plurality of drill pipes. Threaded connections may be flush with the remainder of the drill string outer diameter, but generally have an outer diameter larger than the remainder of the drill string. For example, as shown in FIG. 1, drill string 160 is formed of a long string of threaded pipes 162 joined together with tool joints 164, wherein the tool joints 164 have an outer diameter larger than the outer diameter of the pipes 162. As the drill string is translated through the wellbore and the RCD 100, the sealing element 110 may squeeze against an outer surface of the drill string 160, thereby sealing the wellbore. In particular, the inner diameter of a sealing element is smaller than the objects (e.g., drill pipe, tool joints) that pass through to ensure sealing with zero wellbore pressure. However, the outer geometry of the passive seal creates higher sealing pressure as wellbore pressure increases.
In many prior art RCDs, a Kelly drive is used to rotate the drill string, and thus drill bit. A typical Kelly drive includes a section of polygonal or splined pipe that passes through a mating polygonal or splined bushing and rotary table. The rotary table turns the Kelly bushing, which rotates the Kelly pipe section and the attached drill string. The Kelly pipe-bushing fit allows the pipe to simultaneously rotate and move in a vertical direction. Thus, in RCDs using a Kelly drive, the drill string is rotated using the rotary table in a wrench-like configuration. Because sealing elements used with Kelly drives do not rotate the drill string, sealing element failures in Kelly drives are commonly due to wellbore pressure rather than torsional loading. Conversely, when top drives are used, a sealing element may be used to turn the drill string assembly and to seal the wellbore pressure. Thus, sealing elements used with top drives are subject to failure from a combination of torsional loading and wellbore pressure.
A side and top view of an exemplary sealing element used with a top drive RCD is shown in FIGS. 2A and 2B, wherein a sealing element 200 has an attachment end 210 and a nose end 220. The attachment end is typically attached to a drive-bushing (not shown) using a metal attachment piece, such as a bolt. The nose end 220 has an inner diameter that is smaller than the inner diameter of the attachment end 210 to provide a tight seal against the drillstring. Further, as shown in FIGS. 2A-B, the outer diameter 212 of the attachment end may be larger than the outer diameter 222 of the nose end 220.
Typically, a sealing element is made up of a single elastic material, stripper rubber, which may mechanically deform to seal around various diameters of drill pipe. Conventional sealing element material may include natural rubber, nitrile, butyl or polyurethane, for example, and depends on the type of drilling operation. Additionally, a sealing element may be formed of a fiber reinforced material, such as that described in U.S. Pat. No. 5,901,964.
However, conventional sealing elements in top drive RCDs tend to split or experience chunking when encountering torsion loading or other harsh dynamic conditions due to poor tear resistance. Further, over time the sealing element may become worn and unable to substantially deform to provide a seal around the drill string. Consequently, the sealing element must be replaced, which may lead to down time during drilling operations that can be costly to a drilling operator.
Accordingly, there remains a need to improve the life of seals used for rotating control devices in drilling operations.